Nostrum Oil & Gas PLC (LSE: NOG) (“Nostrum”, or “the Company”), an independent oil and gas company engaging in the production, development and exploration of oil and gas in the pre-Caspian Basin, today announces its financial results in respect of the nine-month period ending 30 September 2017.

Construction of the third Gas Treatment Unit (“GTU3”) is expected to be completed in April 2018

1 IFRS term based on indirect cash flow method2 Defined as profit before tax net of finance costs, foreign exchange loss/gain, ESOP, depreciation, interest income, other income and expenses.3 Defined as cash and cash equivalents including current and non-current investments and excluding restricted cash

Financially the first nine months have been positive with a significant part of our refinancing taking place as well as the higher oil price bringing our revenue in line with what we had budgeted. Operationally it has been disappointing with delays to our major infrastructure project and to our drilling programme combined with declining production. We are working hard to address all these issues and ensuring that we remain focused on delivering the longer term value proposition Nostrum offers.

Other News

Progress on development of GTU3

GTU3 Cash Spent (excl VAT)

As at 30 September 2017

Expenditure to date

US$459 million

Expenditure pre-completion

US$25 million

Expenditure post-completion

US$48 million

Total:

US$532 million

Conference call

Nostrum’s management team will present the 9M 2017 Financial Results and will be available for a Q&A session with analysts and investors today at 14.00 pm BST, 21 November 2017.

If you would like to participate in this call, please register by clicking on the following link and following instructions: Results Call

About Nostrum Oil & Gas
Nostrum Oil & Gas PLC is an independent oil and gas company currently engaging in the production, development and exploration of oil and gas in the pre-Caspian Basin. Its shares are listed on the London Stock Exchange (ticker symbol: NOG). The principal producing asset of Nostrum Oil & Gas PLC is the Chinarevskoye field, in which it holds a 100% interest and is the operator through its wholly-owned subsidiary Zhaikmunai LLP. In addition, Nostrum Oil & Gas holds a 100% interest in and is the operator of the Rostoshinskoye, Darinskoye and Yuzhno-Gremyachenskoye oil and gas fields through the same subsidiary. Located in the pre-Caspian basin to the north-west of Uralsk, these exploration and development fields are situated approximately 60 and 120 kilometres respectively from the Chinarevskoye field.

Forward-Looking Statements
Some of the statements in this document are forward-looking. Forward-looking statements include statements regarding the intent, belief and current expectations of the Partnership or its officers with respect to various matters. When used in this document, the words “expects,” “believes,” “anticipates,” “plans,” “may,” “will,” “should” and similar expressions, and the negatives thereof, are intended to identify forward-looking statements. Such statements are not promises or guarantees, and are subject to risks and uncertainties that could cause actual outcomes to differ materially from those suggested by any such statements.

No part of this announcement constitutes, or shall be taken to constitute, an invitation or inducement to invest in the Company or any other entity, and shareholders of the Company are cautioned not to place undue reliance on the forward-looking statements. Save as required by the Listing Rules and applicable law, the Company does not undertake to update or change any forward-looking statements to reflect events occurring after the date of this announcement.

9M 2017: Nostrum Financial Results

In millions of US$ (unless mentioned otherwise)

9M 2017

9M 2016

Variance

Variance in %

Revenue

303.7

245.1

58.6

23.9%

EBITDA

171.5

142.6

28.9

20.3%

EBITDA margin

56.5%

58.2%

-

(1.7)%

In millions of US$ (unless mentioned otherwise)

9M 2017

H1 2017

Variance

Variance in %

Cash Position

144.4

97.5

46.9

48.1%

Net Debt

912.6

864.3

48.3

5.6%

Revenue, EBITDA and Profit for the Period
Revenue from sales of crude oil, stabilised condensate, LPG and dry gas over the period amounted to US$303.7 million, up 23.9% on the same period last year. EBITDA was US$171.5 million with an EBITDA margin of 56.5%, with a net loss of US$(8.7) million also recorded compared to a loss of US$(64.3) million for 9M 2016.

Cost of sales
The cost of sales was US$146.3 million, an increase from the 9M 2016 figure of US$145.8 million. This is a result of increased royalties and government profit share due to higher revenues and payroll expenses.

Cash resources and Net debt
The Group ended the period with US$144.4 million in cash and cash equivalents (YE 2016: US$101.1 million). Net debt at the end of the period was US$912.6 million (YE 2016: US$857.9 million).

Hedging
In December 2015, Nostrum rolled its pre-existing hedge into a new hedge of 15,000 boepd with a strike price of US$49.16 per barrel. The cost of the hedge was paid entirely from the sale of the Company’s previous hedge for US$92 million. The new hedge has a 24-month tenor, maturing in December 2017, with cash settlements on a quarterly basis. No cash was received from the hedge for the nine-month period ending 30 September 2017.

Sales volumes
The sales volumes split for 9M 2017 was as follows:

Products

9M 2017 sales volumes

(boepd)

9M 2017 Product Mix (%)

Crude Oil & Stabilised Condensate

15,945

40%

LPG (Liquid Petroleum Gas)

4,841

12%

Dry Gas

18,814

48%

Total

39,600

100%

The difference between true production and the sales volumes are as a result from part of the dry gas being used for internal consumption (power generation), gas lift and some losses during raw gas treatment.

During Q3 2017 drilling activity was finished on 2 wells; currently 2 other wells are being completed and stimulation and testing is ongoing on 3 wells

The 2017 drilling programme has been behind schedule and also suffered from delayed results from both appraisal and production wells

Appraisal work has had mixed results so far with successful results from the northern area of the field where we encountered significant pressure and hydrocarbons that suggest there could be material reserves in the north where currently nothing is booked. In the southern areas, we have successfully drilled our planned appraisal wells but have run in to technical issues when retrieving the test results. Workover is being done to try to resolve these issues and show the extent of additional proven reserves within the southern area of the field.

Production has been frustrating in 2017 as we have been unable to return well 217 to full production whilst well 225 has not performed as well as in 2016. In addition, the delay in the drilling schedule has meant that the production wells are not coming on until later in Q4 so we will see continued decline in production without new feedstock. We continue to look for solutions on our best two producers but will also consider re-drilling them next year should there be no success before year end.

Sales volume schedule

2017 and 2018 production is being recalculated due to the delay of GTU3 and the drilling programme being behind schedule. For 2017, it is unlikely sales volumes will exceed 40,000 boepd given the delay in completion of production wells. For 2018, we do not see any increase in production for the first half of the year without GTU3 and taking into account the three-week tie in that will take place in April. For H2 2018 and 2019 we will only be able to guide on this once the drilling programme for 2018 has been finalised and the results from the remaining appraisal wells in 2017 have been obtained.

Longer term guidance as usual is taken from Ryder Scott’s most recent reserve report which assumes production ramping up to 100,000 boepd by 2020

Should oil prices deviate materially the production guidance will be updated accordingly.

Progress on development of GTU3
Due to the delayed delivery of some specially designed valves required for the tie-in of GTU3 with GTU1&2 it will not be possible to bring gas into GTU3 in 2017. The previously planned three week shut down of GTU1&2 has therefore been postponed until after the winter period. The shut down and tie-in is now scheduled to be completed in April 2018. The tie-in will allow gas to go from GTU1&2 into GTU3, for GTU3 to be connected with the export gas pipeline and GTU3 commissioning to take place. Commissioning is expected to be completed within approximately 60 days.

The main reason for the delay is due to the fact that once the tie-in is completed the welding joints need to be hydro-tested prior to any gas passing through it. This testing cannot take place during the winter when temperatures are below zero. In order to minimise the downtime of GTU1&2 it is more efficient to have just one period of downtime to complete the tie-in and the hydro-testing rather than to have two separate periods of shut down for the tie-in and hydro- testing to be carried out separately. Therefore the decision has been taken to move the three week shut down to the period when temperatures move above freezing, which is now forecast to be April 2018.

The result of this change in timing for the tie-in means there will be a very short shut down of GTU1&2 in Q4 2017 as it will be limited to the minimal required maintenance of only a few days. The GTU3 plant on a standalone basis will be mechanically complete well in advance of the forecast tie-in date in April. The postponement of GTU3 commissioning does mean that production guidance for the first six months of 2018 will be impacted as the Company will not be able to increase production above current capacity of 45,000 boepd. Revised full year guidance for production will be given with our 2017 year-end results when the 2018 drilling programme has been set and is under way. The total spend as at 30 September 2017 was US$459 million. The company remains fully funded to complete GTU3 and ramp up production.